In the petroleum drilling and production industry, a string of casing pipe is cemented into a wellbore to provide structural integrity for the bore hole and prevent vertical migration of fluids between formation zones. An additional string of pipe with a smaller chamber, commonly known as production tubing, is usually placed within the casing string as a conduit for the production of fluids out of the well. The downhole string of casing pipe, which may be thousands of feet in length, is made of a plurality of pipe sections which are joined end to end by threaded connections. The pipe joints, also called collars, have increased mass as compared to the pipe sections. After the sections of pipe have been cemented into the well, logging tools are run to determine the location of the casing collars. The logging tools used include a pipe joint locator whereby the depth is recorded of each of the pipe joints through which the logging tools are passed. The logging tools generally also include a gamma ray logging device which records the depths and the levels of naturally occurring gamma rays that are emitted from various well formations. The casing collar and gamma ray logs are correlated with previous open hole logs which results in an accurate record of the depths of the pipe joint across the subterranean zones of interest and is typically referred to a tally log.
It is often necessary to accurately determine the location of one or more casing collar joints in a well. This need arises, for example, when it is desired to isolate strata with packers and perforate the well casing between the packers within a producing stratum of the formation, or to identify expansion joints, gas-lift valves, etc.
In order to identify casing collar joints, an appropriate well tool is lowered into well casing on a length of tubing, either coiled or jointed. Given the need for precision as to the depth, pipe joint depth information available from previously recorded joint and tally logs taken during well drilling is not sufficiently accurate. Regardless of the care and precision taken during the drilling process, true depth measurements are affected by tubing elasticity, stretch, thermal expansion, non-linearity of the well bore and the casing itself, and other variable regularities. Similarly, the accurate depth of the tubing string lowered into the well is also subject to error from the same causes. In the case of coiled tubing used to lower well tools, there is a tendency to spiral due to forcing the coil down or along a horizontal section of the well.
A variety of pipe string joint indicators have been developed including slick line indicators that can produce drag inside the pipe string and wire line indicators that send an electronic signal to the surface by the way of electric cable and others. These devices, however, either cannot be utilized as a component in a coiled tubing system or have disadvantages when so used. Wireline indicators do not work well in highly deviated holes because they depend on the force of gravity to position the tool. In addition, the wire line and slick line indicators take up additional rig time when used with jointed tubing.
In recent years, there have been more sophisticated systems and methods devised to improve accuracy of collar locators. These include systems and methods employing magnetic field measurements. While such inventions have advanced the art, there remain problems in the field. For example, certain collar locators operate on the well known principle that an electromotive force (emf) is induced in a coil that is either stationary in a magnetic field that varies in intensity or is moving with respect to a constant magnetic field. Conventional casing collar locators of this type typically rely on the generation of a relatively powerful magnetic field from the locator using either permanent magnet or a coil through which electrical current is passed to induce magnetism. In the latter case, a significant amount of power is required to generate a magnetic field. As the coil passes adjacent to a collar, the flux density of the magnetic field is changed by the additional thickness of the collar. This change is detected by the sensor in the form of a variation in the electromotive force (emf) generated in a coil. The electrical signal is telemetered to the surface and analyzed to determine sensor depth.
Conventional casing collar locators are subject to operational disadvantages and limitations of their effectiveness. They operate, for example, only in a dynamic mode, because the current induced in the coil requires that the sensor move with respect to the casing. If the device is moved too slowly, the changes in emf become subject to signal-to-noise ratio problems, effectively degrading their accuracy. On the other hand, in a rapidly moving sensor, signal strength may be problematic. In any event, the precise location of the sensor is itself lowered by the necessity of pinning down the position of a moving object at any given moment. Other problems are associated with the generation of strong magnetic fields in the wellhole, such as interfering with other instrumentation.
Although methods and apparatus has been known in the past to identify downhole casing collars and problem points of casing corrosion, a need exists for enhanced joint locator and/or pipe corrosions locator information. The foregoing is not intended to identify all of the problems and limitations of previously known systems but should be sufficient to demonstrate that collar and corrosion location systems existing in the past will admit to worthwhile improvement.